In the recovery of oil from subterranean, oil-bearing formations or reservoirs, it is usually possible to recover only a limited proportion of the original oil present in the reservoir by the so-called primary recovery methods which utilize the natural formation pressure to produce the oil through suitable production wells. For this reason, a variety of supplementary recovery techniques have been employed, directed either to maintaining formation pressure or to improving the displacement of the oil from the porous rock matrix. Techniques of this kind have included formation pressurization, thermal recovery methods such as steam flooding and in situ combustion, water flooding and miscible flooding techniques.
In miscible flooding operations, a solvent is injected into the reservoir to form a single phase solution with the oil in place so that the oil can then be removed as a more highly mobile phase from the reservoir. This provides extremely effective displacement of the oil in the areas through which the solvent flows, so that an extremely low residual saturation is obtained. The efficiency of this process derives from the fact that under the conditions of temperature and pressure prevailing in the reservoir, a two-phase system within the reservoir between the solvent and the reservoir oil is eliminated. When this happens the retentive forces of capillarity and interfacial tension which are significant factors in reducing the recovery efficiency of oil in conventional flooding operations where the displacing agent and the reservoir oil exist as two separate phases, are eliminated or substantially reduced.
Miscible recovery operations are normally carried out by a displacement procedure in which the solvent is injected into the reservoir through an injection well to displace the oil from the reservoir towards a production well from which the oil is produced. Because the solvent, typically a light hydrocarbon such as liquid petroleum gas (LPG) or a paraffin in the C.sub.2 to C.sub.6 range, may be quite expensive, it is often desirable to carry out the recovery by injecting a slug of the solvent, followed by a cheaper displacement liquid such as water. However, the economics of miscible recovery operations using first contact miscible solvents such as LPG or light hydrocarbons are quite unattractive.
Of the various miscible recovery processes so far used or proposed, flooding by carbon dioxide is considered to be of substantial promise. In the carbon dioxide flooding technique, a slug of carbon dioxide is injected into the formation to mobilize the oil and permit it to be displaced towards a production well. Carbon dioxide is considered a miscible-type flooding agent because under supercritical conditions, usually high pressure, carbon dioxide acts as a solvent and in certain reservoir situations, has a great advantage over more common fluids as a displacement agent. Even under conditions where the carbon dioxide is not wholly effective as a solvent for the oil, recovery may be improved by taking advantage of the solubility of carbon dioxide in the oil, causing a viscosity reduction and a swelling of the oil, which leads to increased recovery. These effects have been utilized at pressures much lower than the miscibility pressures for carbon dioxide and oil. Processes using carbon dioxide as a recovery agent are described in U.S. Pat. Nos. 3,811,501, 3,811,502, 3,497,007, 4,299,286 and 4,410,043.
Carbon dioxide is not a first contact miscible solvent like LPG or a light hydrocarbon, which forms a single phase solution with the reservoir when the two come into contact, i.e. upon their first contact. Rather, carbon dioxide is a multiple contact miscible solvent which forms a single phase only after a period of time during which the carbon dioxide first preferentially extracts the light hydrocarbons containing from two to six carbon atoms from the crude oil, thereby developing a hydrocarbon-containing solution at the interface between the carbon dioxide and the crude oil. This solution is able to dissolve other, heavier hydrocarbons, i.e. C.sub.6+ hydrocarbons and these progressively enter the solution to form the desired single phase which is then carried forward through the reservoir, progressively dissolving heavier hydrocarbons as it advances. Thus, as the flooding front advances through the reservoir, the composition of the displaced fluid gradually changes from the crude oil to that of the pure carbon dioxide.
Multiple contact miscibility is a function of the pressure of the system and the minimum pressure required to achieve multiple contact miscibility is called the minimum miscibility pressure of MMP. This varies according to the nature of the oil and of the solvent and in accordance with certain other factors. In some reservoirs, the minimum miscibility pressure may be unattainable due to factors such as low overburden pressure or the impracticality of pressurizing the reservoir. The presence of impurities, such as nitrogen or methane, may increase the MMP to levels beyond those attainable at reservoir conditions. For example, ten mole percent methane in CO.sub.2 increased the MMP of a West Texas oil from 1200 to 1800 psi. The same amount of nitrogen increased the MMP of the same oil to 3300 psi (Stalkup, F.I., Miscible Displacement, SPE Monograph, Volume 8, page 141, Table 8.1, 1983). If the minimum miscibility pressure cannot be achieved in the reservoir, the flooding process will be immiscible in character and recovery from the solvent injection will be low.
The minimum miscibility pressure of carbon dioxide and other solvents may be decreased by the use of additives such as various low molecular weight hydrocarbons, e.g. C.sub.2 to C.sub.6 paraffins and the use of these additives may permit miscible flooding to be carried out in reservoirs which do not premit the minimum miscibility pressure to be attained. Although the use of a solubility additive of this kind is undoubtedly favorable, it does have the disadvantage of making the process less economically attractive since the additives are not completely recovered from the reservoir and to this extent, their cost must be considered in the economics of the process. It would therefore be desirable to minimize the amount of the solubility additive which needs to be used.